Higher Recovery Factor Research Articles

Systematical study on dimethyl ether as a renewable solvent for warm VAPEX and its significant implications for the heavy oil industry

As part of its Healthy Environment and Healthy Economy (HEHE) plan to address climate change, the Canadian government intends to increase the carbon tax from its current level of $30 per tonne to $170 per tonne over the next nine years. To respond to this plan positively, oil companies have started to address the most significant issue on carbon emissions from their current oil recovery processes, such as steam assisted gravity drainage (SAGD), by utilizing more environmentally responsive processes. Vapor extraction (VAPEX) was proposed as an alternative method; however, its previous studies were limited to a conventional solvent (n-alkane), which is not economically feasible. Dimethyl ether (DME), an emerging renewable chemical resource, was initially proposed as a solution to reduce carbon emissions and aroused interest in the heavy oil industry. But limited research has been carried out for understanding and evaluating DME’s performance in heavy oil recovery.In this study, essential mechanisms including asphaltene deposition, reservoir responses due to solvent injection or solid adsorption, and mass transfer by considering water phase solubility during DME injection have been studied by numerical simulation. Moreover, production performance, in-situ upgraded oil and energy efficiency have been compared among SAGD, conventional propane VAPEX and DME as a novel solvent for warm VAPEX. DME has been evaluated as a promising solvent for heavy oil and bitumen recovery with a less negative blockage effect, a higher recovery factor and rate, higher API upgrading, and higher energy efficiency compared with a conventional solvent. DME, as a renewable, amphoteric chemical solvent, will lead to significant implications in addressing the challenges brought by carbon emissions.

Optimization of triple-alternating-gas (TAG) injection technique for enhanced oil recovery in tight oil reservoirs

After single-gas (SG) injection operations in tight oil reservoirs, a significant amount of oil is still unrecovered. To increase productivity, several sequencing gas injection techniques have been utilized. Given the scarcity of research on multiple-gas alternating injection schemes, this study propose an optimized triple-alternating-gas (TAG) injection for improved oil recovery. The performance of the TAG process was demonstrated through numerical simulations and comparative analysis. First, a reservoir compositional model is developed to establish the properties and composition of the tight oil reservoir; then, a suitable combination for the SG, double alternating gas (DAG), and TAG was selected via a comparative simulation process. Second, the TAG process was optimized and the best case parameters were derived. Finally, based on the oil recovery factors and sweep efficiencies, a comparative simulation for SG, DAG, and TAG was performed and the mechanisms explained. The following findings were made: (1) The DAG and TAG provided a higher recovery factor than the SG injection and based on recovery factor and economic advantages, CO2 + CH4 + H2S was the best choice for the TAG process. (2) The results of the sensitivity analysis showed that the critical optimization factors for a TAG injection scheme are the injection and the production pressures. (3) After optimization, the recovery factor and sweep efficiency of the TAG injection scheme were the best. This study promotes the understanding of multiple-gas injection enhanced oil recovery (EOR) and serves as a guide to field design of gas EOR techniques.

Co-Optimization of CO2 Storage and Enhanced Gas Recovery Using Carbonated Water and Supercritical CO2

CO2-based enhanced gas recovery (EGR) is an appealing method with the dual benefit of improving recovery from mature gas reservoirs and storing CO2 in the subsurface, thereby reducing net emissions. However, CO2 injection for EGR has the drawback of excessive mixing with the methane gas, therefore, reducing the quality of gas produced and leading to an early breakthrough of CO2. Although this issue has been identified as a major obstacle in CO2-based EGR, few strategies have been suggested to mitigate this problem. We propose a novel hybrid EGR method that involves the injection of a slug of carbonated water before beginning CO2 injection. While still ensuring CO2 storage, carbonated water hinders CO2-methane mixing and reduces CO2 mobility, therefore delaying breakthrough. We use reservoir simulation to assess the feasibility and benefit of the proposed method. Through a structured design of experiments (DoE) framework, we perform sensitivity analysis, uncertainty assessment, and optimization to identify the ideal operation and transition conditions. Results show that the proposed method only requires a small amount of carbonated water injected up to 3% pore volumes. This EGR scheme is mainly influenced by the heterogeneity of the reservoir, slug volume injected, and production rates. Through Monte Carlo simulations, we demonstrate that high recovery factors and storage ratios can be achieved while keeping recycled CO2 ratios low.

High Purity of α-Lactalbumin from Binary Protein Mixture by Charged UF Membrane Far from the Isoelectric Point to Limit Fouling

Separation and high recovery factor of proteins similar in molecular mass is a challenging task, and heavily studied in the literature. In this work, a systematic study to separate a binary protein mixture by charged ultrafiltration membranes without affecting membrane performance was carried out. α-lactalbumin (ALA, 14.4 kDa) and β-lactoglobulin (BLG, 18.4 kDa) were used as a binary model system. These two proteins are the main proteins of whey, a very well-known byproduct from the dairy industry. Initially, a systematic characterization of individual proteins was carried out to determine parameters (protein size and aggregation, zeta potential) which could influence their passage through a charged membrane. Then, the influence of operating parameters (such as initial protein concentration, pH, and critical pressure) on the UF process was investigated, so as to identify conditions that limit membrane fouling whilst maximizing protein recovery factor and purity. The study permitted to identify process conditions able to fully separate ALA from BLG, with high purity (95%) and recovery factor (80%), in a single UF step. Compared to studies reported in literature, here, the main approach used was to carry out a charged UF process far from proteins isoelectric point (pI) to limit protein aggregation and membrane fouling.

Experimental Study on the EOR Performance of Imbibition and Huff and Puff in Fractured Tight Oil Reservoirs

AbstractInjection of imbibition fluids or CO2 during hydraulic fracturing is an effective stimulation method for tight oil reservoirs. Selecting appropriate agents is significant to optimize the integrated scheme of fracturing and production in tight oil reservoirs. In this study, a series of lab experiments, including spontaneous imbibition, dynamic imbibition, and huff and puff, were carried out using real tight cores, water absorption apparatus, and core flooding equipment. The EOR performances of imbibition fluids and CO2 in fractured tight cores were compared. The mass transfer of imbibition fluids and CO2 in tight oil reservoirs and its influence on the sweeping volume and EOR mechanisms were discussed. The results show that (1) the spontaneous imbibition rate of imbibition fluids in tight cores is slow, and the oil recovery factor by spontaneous imbibition in cracked cores is relatively high, up to 13.42%. (2) In the dynamic imbibition experiments, the final oil recovery by CO2 injection was significantly higher than that by injecting imbibition liquids. Because of the excellent miscibility effect of CO2, oil production by CO2 injection mainly occurred in the primary displacement stage. Comparatively, the EOR effect of imbibition fluids mainly played its role during production after well shut-in, which can increase the oil recovery factor by 7.35%-11.64%. (3) The influence of the huff and puff mode of CO2 on EOR performance is greater than that of imbibition fluids due to its more sensitive compressibility and mass transfer rate. Generally, a high oil recovery factor can be obtained if the depletion production is conducted first, and a huff and puff operation is followed. (4) Comprehensively understanding the mass transfer characteristics of CO2 and imbibition fluids in tight oil reservoirs can guide the fracturing parameter design, such as the order of fracturing fluid slugs, the optimal soak time, and fracture spacing.

Differential evolution for early-phase offshore oilfield design considering uncertainties in initial oil-in-place and well productivity

• Differential evolution optimization of number of wells, plateau rate and NPV. • Multi-objective optimization considering ultimate recovery factor and NPV. • The NPV distribution average can be estimated with the average of the variables. • Method provides decision support to field planners in early field development. During the early phases of offshore oil field development, field planners must decide upon general design features such as the required number of wells and maximum oil processing capacity (field plateau rate), usually by performing sensitivity studies. These design choices are then locked in subsequent development stages and often prevent from achieving optimal field designs in later planning stages when more information is available and uncertainties are reduced. In the present study, we propose using numerical optimization of net present value (NPV) to advice field planners when deciding on the appropriate number of wells, maximum oil processing capacity (plateau rate) in a Brazilian offshore oil field. Differential Evolution (DE) is employed for solving the optimization models. The uncertainties considered are well productivity and initial oil-in-place, handled by (1) using the mean of the distributions and (2) Monte Carlo simulation. A multi-objective optimization was also formulated and solved including ultimate recovery factor in addition to net present value. The proposed method successfully computes probability distributions of optimal number of wells, plateau rate and NPV. If one wishes to compute the mean of such distributions only, for most cases it is adequate to run an optimization using the mean of the input values instead of performing Monte Carlo sampling. The multi-objective optimization allows to find field designs with high ultimate recovery factor and high NPV. In this case, the value of NPV is similar to the optimum NPV value when optimizing NPV only. The methods described could provide decision support to field planners in early stages of field development.

NUMERICAL STUDY OF THE POLYMER INJECTION ON DISPLACEMENT OF HIGH-VISCOUS OIL FROM CARBONATE FORMATION

Residual recoverable reserves of high-viscosity and heavy oils in the Republic of Kazakhstan amount to about 340 million tons. The main oil fields containing high-viscosity and heavy oil are Karazhanbas, Kenkiyak, Zhetybai, North Buzachi, Kenbai, etc. Improving the system for the development of high-viscosity oil fields and the selection of rational EOR is relevant for Kazakhstan, as this will increase the efficiency of their development. Given the high resource potential of such fields, it is necessary to develop and introduce new technologies in the development of high-viscous oil fields using enhanced oil recovery methods. To ensure high oil recovery factors, it is necessary to carefully select the EOR applicable to high-viscosity oil fields at an early stage of their development. This work is devoted to the problem of EOR selection in the development of high-viscosity oil fields. For the research polymer injection was selected. Evaluation of the efficiency of the proposed EOR was carried out based on the results of numerical experiments to displace high-viscosity oil with the creation of reservoir conditions. As a result, the aqueous polymer solution with the concentration of 0.05 % yielded 51% of oil recovery, whereas water injection recovered only 10% of oil. However, the interaction of the polymer with high-viscosity oil has not been deeply studied, which is relevant to the fields of Kazakhstan.

Technology Focus: Oilfield Chemistry (September 2021)

As production chemists, we are all aware of the overall concepts of improved oil recovery (IOR) and enhanced oil recovery (EOR). Perhaps, though, fewer of us are aware of the different idiosyncrasies that exist within (and even between) these two broad categories of recovery and then how chemistry and chemicals can have an effect upon these processes. I would like to propose that the lines once were quite distinct between IOR and EOR: IOR was a standard waterflood operation, and EOR (from a chemist’s perspective) was the addition of chemistry to that waterflood (typically polymer or surfactant). Nowadays, the science has evolved massively to create many sub-genres of IOR and EOR. A waterflood is rarely just a waterflood anymore. We can alternate water and gas injection. We can add chemical conformance aids to direct better the flow of water. We can change the salinity of the water to promote better wettability for higher recovery factors. The list goes on. One just has to search out the number of EOR papers vs. (pretty much) every other discipline of production chemistry to see the commitment this industry still has to the research of this discipline. In recent years, the focus has tended to move away from deep-reservoir EOR to focus on near-wellbore stimulation. Interestingly, the mechanistic considerations that we make as production chemists are nearly identical in all cases, and significant synergies exist between these subdisciplines. Therefore, from the recent research published by SPE, two focused topics of IOR/EOR have arisen: the use of nanoparticles and the use of water-shutoff technologies. Nanoparticle use is gaining significant traction in the oil and gas industry, and field applications are now being reported. The area of IOR/EOR is no exception. Water shutoff is not a new technology area. However, are these established, production-sustaining IOR techniques seeing a resurgence caused by the headwinds our industry has faced during the COVID-19 pandemic? Recommended additional reading at OnePetro: www.onepetro.org. OTC 30123 - Thermal and Rheological Investigations on N,N’-Methylenebis Acrylamide Cross-Linked Polyacrylamide Nanocomposite Hydrogels for Water-Shutoff Applications by Mohan Raj Keishnan, Alfiasal University, et al. IPTC 20210 - Chemical and Mechanical Water Shutoff in Horizontal Passive ICD Wells: Experience and Lessons Learned in Giant Darcy Reservoir by Mohamed Abdel-Basset, Schlumberger, et al. SPE 203831 - Efficient Preparation of Nanostarch Particles and Mechanism of Enhanced Oil Recovery in Low-Permeability Oil Reservoirs by Lei Zhang, China University of Geosciences, et al.

Effects of miscible CO2 injection on production recovery

Carbon dioxide (CO2) injection is implemented into the reservoir to further improve the oil production efficiency, by mixing with oil at reservoir condition, and becomes miscible. The miscibility affects the oil to become swelled and less viscous and thus easily flow through the reservoir. Most of the (CO2) EOR projects has higher recovery factor in miscible condition. Therefore, this article aims to determine the effects of the miscible (CO2) injection on production recovery in the Cornea Field. The Cornea Field is located in Browse Basin, Western Australia. It is a simple trap structure which is elongated and formed by unfaulted drape anticline over an eroded high basement. The importance of this research is that (CO2) injection has not been implemented in the Cornea Field since it is a complex reservoir. However, research showed that there was a high potential production recovery in this field. Therefore, research needs to be conducted to determine the effectiveness of the (CO2) injection on production recovery in this field. The model was validated, by comparing MMP obtained from the simulation model and correlation methods. The MMP of this reservoir is above 38 Bar. Sensitivity analysis on reservoir pressure, reservoir temperature and (CO2) injection rate was investigated. Oil production increases with the increase in reservoir pressure and reservoir temperature. As the (CO2) injection rate increases, oil production also increased. From the result, hence, this study should contribute to the knowledge gap in Cornea Field.

Water and salts recovery from desalination brines: An exergy evaluation

Exergy analyses are becoming important tools in identifying the less efficient components of plants through the evaluation of the energy lost in entropy production. In this work, this type of analysis was considered for desalination plants based on membrane operations, with specific emphasis on membrane distillation and membrane crystallization for the improvement of the water recovery factor and the recovery of valuable salts from produced brines. The state of the art in the field was firstly presented and discussed. In all literature works, the thermal supply was the highest contributor to exergy losses. However, the use of waste heat or renewable energies can significantly improve the exergy efficiency of the process, as the feed is heated by the available source and enters the process already at the desired temperature. Furthermore, it resulted that the gain for the sale of salts produced by membrane crystallization was able to cover the desalination costs, even without waste heat availability.Then, the exergy analysis of membrane distillation (MD) and membrane crystallization (MCr) working on four different feeds was experimentally carried out. Commercial modules equipped with capillary polypropylene membranes (0.2 µm pore size) were used at fixed feed temperature and flow rate. A high exergy efficiency (72%) was obtained with the Synthetic RO feed (79.9 g/L), together with a high water recovery factor (79%) and brine concentration (around 476 g/L).

Potential Application of CO2 for Enhanced Condensate Recovery Combined with Geological Storage in the Depleted Gas-Condensate Reservoirs

Abstract CO2 emissions are considered to be the main contributor to global warming and climate change. One of the ways reducing the emissions to atmosphere is a proper capture and further geological storage of the carbon dioxide. In the oil industry, CO2 is used as one of the injection agents to displace oil and enhance its recovery. Due to the low multi-contact miscibility pressure between CO2 and hydrocarbons, fully miscible condition is quickly reached, leading to efficient displacement and high recovery factors. The utilization of the depleted gas fields for CO2 storage, however, is considered as the option that is more expensive compared to oil field, since the enhanced recovery of gas with CO2 is not effective. For this reason, our study considers the potential use of CO2 EOR in depleted gas-condensate fields. This potential is evaluated by performing numerical simulations for the typical-size gascondensate reservoirs with no active aquifer, in order to estimate both the storage efficiency and the additional oil recovery from condensed C5+ hydrocarbon fractions, that otherwise will be never recovered and lost in the reservoir. Obtained results indicate significant potential for CO2 storage and additional condensate recovery from the typical gas-condensate field of Eastern Ukraine.

Organic solvent-free elevated temperature liquid–liquid extraction combined with a new switchable deep eutectic solvent-based dispersive liquid–liquid microextraction of three phenolic antioxidants from oil samples

An organic solvent-free extraction procedure using elevated temperature liquid–liquid extraction/ dispersive liquid–liquid microextraction based on deep eutectic solvent has been performed for the extraction of three synthetic phenolic antioxidants from oil samples. In the developed approach, firstly the antioxidants were extracted into an aqueous alkaline solution in an elevated temperature. Then, a few microliters of deep eutectic solvent formed from tetrabutylammonium chloride and hydroquinone was dissolved in the alkaline solution and a homogenous solution was obtained. In the following it was dispersed into an acidic solution. In this step, an acid–base reaction was occurred and the analytes were migrated into the fine droplets of the deep eutectic solvent. The extracted analytes were determined by gas chromatography-flame ionization detector. Validation data showed that low limits of detection (0.13–0.42 ng/mL) and quantification (0.36–1.41 ng/mL), high extraction recovery (74–89%) and enrichment factor (370–445), and good precision (relative standard deviation ≤ 7.4%) can be obtained by the developed method. Finally, the method was used for quantification of the antioxidants in several edible oil samples.

Pore-Scale Imaging and Analysis of Wettability Order, Trapping and Displacement in Three-Phase Flow in Porous Media with Various Wettabilities

Three-phase flow in porous media is encountered in many applications including subsurface carbon dioxide storage, enhanced oil recovery, groundwater remediation and the design of microfluidic devices. However, the pore-scale physics that controls three-phase flow under capillary dominated conditions is still not fully understood. Recent advances in three-dimensional pore-scale imaging have provided new insights into three-phase flow. Based on these findings, this paper describes the key pore-scale processes that control flow and trapping in a three-phase system, namely wettability order, spreading and wetting layers, and double/multiple displacement events. We show that in a porous medium containing water, oil and gas, the behaviour is controlled by wettability, which can either be water-wet, weakly oil-wet or strongly oil-wet, and by gas–oil miscibility. We provide evidence that, for the same wettability state, the three-phase pore-scale events are different under near-miscible conditions—where the gas–oil interfacial tension is ≤ 1 mN/m—compared to immiscible conditions. In a water-wet system, at immiscible conditions, water is the most-wetting phase residing in the corners of the pore space, gas is the most non-wetting phase occupying the centres, while oil is the intermediate-wet phase spreading in layers sandwiched between water and gas. This fluid configuration allows for double capillary trapping, which can result in more gas trapping than for two-phase flow. At near-miscible conditions, oil and gas appear to become neutrally wetting to each other, preventing oil from spreading in layers; instead, gas and oil compete to occupy the centre of the larger pores, while water remains connected in wetting layers in the corners. This allows for the rapid production of oil since it is no longer confined to movement in thin layers. In a weakly oil-wet system, at immiscible conditions, the wettability order is oil–water–gas, from most to least wetting, promoting capillary trapping of gas in the pore centres by oil and water during water-alternating-gas injection. This wettability order is altered under near-miscible conditions as gas becomes the intermediate-wet phase, spreading in layers between water in the centres and oil in the corners. This fluid configuration allows for a high oil recovery factor while restricting gas flow in the reservoir. Moreover, we show evidence of the predicted, but hitherto not reported, wettability order in strongly oil-wet systems at immiscible conditions, oil–gas–water, from most to least wetting. At these conditions, gas progresses through the pore space in disconnected clusters by double and multiple displacements; therefore, the injection of large amounts of water to disconnect the gas phase is unnecessary. We place the analysis in a practical context by discussing implications for carbon dioxide storage combined with enhanced oil recovery before suggesting topics for future work.

Improvement of Displacement Efficiency in Heavy Oil Reservoirs With Enzyme

Abstract In this study, a systematical technique has been developed to experimentally and numerically evaluate the displacement efficiency in heavy oil reservoirs with enzyme under different conditions. First, dynamic interfacial tensions (IFTs) between enzyme solution and heavy oil are measured with a pendant-drop tensiometer, while effects of pressure, temperature, enzyme concentration, and contact time of enzyme and heavy oil on equilibrium IFT were systematically examined and analyzed. After waterflooding, enzyme flooding was carried out in sandpacks to evaluate its potential to enhance heavy oil recovery at high water-cut stage. Numerical simulation was then performed to identify the underlying mechanisms accounting for the enzyme flooding performance. Subsequently, a total of 18 scenarios were designed to simulate and examine effects of the injection modes and temperature on oil recovery. Except for pressure, temperature, enzyme concentration, and contact time are found to impose a great impact on the equilibrium IFTs, i.e., a high temperature, a high enzyme concentration, and a long contact time reduce the equilibrium IFTs. All three enzyme flooding tests with different enzyme concentrations show the superior recovery performance in comparison to that of pure waterflooding. In addition to the IFT reduction, modification of relative permeability curves is found to be the main reason responsible for further mobilizing the residual heavy oil. A large slug size of enzyme solution usually leads to a high recovery factor, although its incremental oil production is gradually decreased. In addition, temperature is found to have a great effect on the recovery factor of enzyme flooding likely owing to reduction of both oil viscosity and IFT.

A Single-Well Gas-Assisted Gravity Drainage Enhanced Oil Recovery Process for U.S. Deepwater Gulf of Mexico Operations

The U.S. Deepwater Gulf of Mexico (DGOM) area that has some of the most prolific oil reservoirs is still awaiting the development of a viable enhanced oil recovery (EOR) process. Without it, DGOM will remain severely untapped. Exorbitant well costs, in excess of $200 million, preclude having extensive injection patterns, commonly used in EOR design frameworks. Aside from injection patterns, even operationally waterflooding has met with significant challenges because of injectivity issues in these over pressurized turbidities. The gas-assisted gravity drainage (GAGD) EOR process, that holds promise for deepwater environments because of lesser injectivity issues, among others, has been adapted in this work to overcome these limitations. A novel design in the form of a single well—gas assisted gravity drainage (SW-GAGD) process, has been demonstrated to emulate the benefits of a GAGD process in a cost-effective manner. Unlike conventional GAGD processes, which need multiple injectors and separate horizontal production wells, the SW-GAGD process just uses a single well for injection and well production. The performance of the process has been established using partially scaled visual glass models based on dimensional analyses for scale up of the process. The recovery factor has been shown to be in the range of 65–80% in the immiscible mode alone, and the process is orders of magnitude faster than natural gravity drainage. A toe-to-heel configuration of the SW-GAGD process has also been tested and for the configuration to be immune from reservoir layering, the toe of the well should ideally end at the top of the payzone. Better sweep of the payzone and consequent high recovery factor of 80% OOIP was observed, if the heel part of the bottom lateral is located in a lower permeability zone.

Study of a low-damage efficient-imbibition fracturing fluid without flowback used for low-pressure tight reservoirs

The oil production from the low-pressure tight reservoirs in China decreases sharply after fracturing under natural depletion. To supply the formation energy and displace oil through imbibition instead of flowback, a novel nanoparticle-enhanced supramolecular fracturing fluid (NESF) was developed. It consisted of 0.10 wt% hydrophobically modified hydroxypropyl guar (HMHPG), 1.00 wt% synthesized hydrophilic gemini surfactant (HGS), and 0.05 wt% hydrophobically fumed nanosilica (HNS). A series of experiments were conducted to characterize the molecular structure of HGS and evaluate the heat/shear resistance, rheological property, proppant suspension and transportation, formation damage, and imbibition efficiency of NESF. Finally, the oilfield practical application of NESF fracturing without flowback was carried out. The results showed that the heat resistance and the interfacial property of NESF were improved by HNS and HGS respectively. Besides the favorable common properties, a low oil permeability loss rate of 9.40%, a high fracture conductivity retainment rate of 95.11%, and a high imbibition recovery factor of 19.43% were realized by NESF. The accumulative oil production of the well stimulated by NESF without flowback was increased by 13.55% and the decline rate of oil production was reduced from 14.70% to 5.22% in the first 6 months.

Adsorption capacity of nitrate from artificial fertilizers and soil on pyrophyllite

The study at hand presents for the first time the use of pyrophyllite as adsorbent for nitrate removal from soil and artificial fertilizers. A series of column and batch adsorption experiments were conducted to examine the effects of the adsorbent’s various parameters, the contact time, pH of the solution, the initial concentration of nitrate, concentration and adsorbent granulometry. Pyrophyllite fractions of 0.25, 0.50 and 1.00 mm had very similar pH values of aqueous suspensions and were in the weakly basic range. Nitrate adsorption capacity on pyrophyllite expressed by recovery factor values ranges from 93.14 to 99.77%. High recovery factor values from 90.44 to 97.45% for 1, 3, 5 and 8 mL min−1 flow rates were obtained using all pyrophyllite fractions. Nitrate removal was very effective by the contact time of 1 and 2 h, and the recovery factor values were in the range of 90.38–91.47% and 92.15–93.18% for a contact time of 1 h and 2 h, respectively. In addition, elution of nitrate from pyrophyllite was performed using the following solution with different pH values: 1.70 (synthetic gastric juice), 6.40 (rainwater), 7.70 (distilled water), 9.30 and 12.50 (NaOH solution). Elution was very low for all used solutions and was the highest at the pH 9.30. The results show that the use of pyrophyllite for removal of nitrate from artificial fertilizers and soil was an adequate approach because it has a high nitrate adsorption capacity, while the nitrate elution from the pyrophyllite was very low.

Membrane Crystallization and Membrane Condenser: Two Membrane Contactor Applications

In recent years different new membrane processes have been designed and developed. In this paper two innovative processes (i.e., membrane condenser and membrane crystallization) will be described and discussed. Membrane crystallization can be used in desalination in combination with membrane distillation and pressure driven membrane processes (such as nanofiltration or reverse osmosis) to achieve high recovery factor combined to salt crystals production.The innovative membrane condenser can be used for the selective recovery of evaporated waste water and contaminants from industrial gases. This process can be also used for pre-treating gas streams that require further separation for the recovery of a defined species (such as pre-treatment of flue gas when used for CO2 capture, biogas for bio methane production, etc.). The current status, the separation principle, the utilized membrane materials and membrane configurations, and the application fields are described and discussed. The future development direction of these two processes is also given. Keywords: Membrane Crystallization; Membrane Condenser; Water recovery; Membrane Technologies;

Experimental study of enhanced oil recovery by CO2 huff-n-puff in shales and tight sandstones with fractures

The fractures and kerogen, which generally exist in the shale, are significant to the CO2 huff-n-puff in the shale reservoir. It is important to study the effects of fractures and kerogen on oil recovery during CO2 huff-n-puff operations in the fracture–matrix system. In this study, a modified CO2 huff-n-puff experiment method is developed to estimate the recovery factors and the CO2 injectivity in the fractured organic-rich shales and tight sandstones. The effects of rock properties, injection pressure, and injection time on the recovery factors and CO2 usage efficiency in shales and sandstones are discussed, respectively. The results show that although the CO2 injectivity in the shale is higher than that in the sandstone with the same porosity; besides, the recovery factors of two shale samples are much lower than that of two sandstone samples. This demonstrates that compared with the tight sandstone, more cycles are needed for the shale to reach a higher recovery factor. Furthermore, there are optimal injection pressures (close to the minimum miscible pressure) and CO2 injection volumes for CO2 huff-n-puff in the shale. Since the optimal CO2 injection volume in the shale is higher than that in the sandstone, more injection time is needed to enhance the oil recovery in the shale. There is a reference sense for CO2 huff-n-puff in the fractured shale oil reservoir for enhanced oil recovery (EOR) purposes.

New Polymer Inclusion Membrane in the Separation of Nonferrous Metal Ion from Aqueous Solutions

The new polymer inclusion membrane (PIM) with ethylenediamine-bis-acetylacetone (EDAB-acac) matrix was used for the separation of Zn(II) solutions containing non-ferrous metal ions (Co(II), Ni(II) Cu(II), Cd(II)). The effective conditions for carrying out transport studies by PIMs were determined on the basis of solvent extraction studies. The values of the stability constants and partition coefficients of M(II)-EDAB-acac complexes were determined from the extraction studies. The stability constants increase in series Ni(II) < Cu(II) < Co(II) < Cd(II) < Zn(II), and their logarithms are 8.85, 10.61, 12.73, 14.50, and 16.84, respectively. The transport selectivity of the PIMs were: Zn(II) > Cd(II) > Co(II) > Cu(II) > Ni(II). The established stability constants of the complexes also decrease in this order. The values of three parameters: initial flux, selectivity coefficient, and recovery factor of a given metal after 12 h were selected for the comparative analysis of the transport process. The highest values of the initial fluxes were received for Zn(II), Cd(II), and Co(II). They are, depending on the composition of the mixture, in the range 9.87–10.53 µmol/m2, 5.26–5.61 µmol/m2, and 7.43–7.84 µmol/m2 for Zn(II), Co(II), and Cd(II), respectively. The highest recovery factors were observed for Zn(II) ions (90–98.0%). For Cd, Co and Cu, the recovery factors are high and are within the range 76–83%, 64–79%, and 51–66%, respectively.